Log and core data are routinely used by petrophysicists to analyze the lithology, porosity and saturation of oil and gas reservoirs. Log and core data can deliver results in the form of volume fractions of lithological or mineralogical components, porosity, and relative fractions of fluids present in a rock formation. However, this volumetric and compositional analysis does not address the geometric distribution of the mineralogical components.
FIG. 1 depicts various graphs showing a conventional petrophysical analysis solving for sand, shale, porosity and fluid saturations. The data plotted in FIG. 1 is derived from a simple logging suite includes resistivity, gamma ray, density and thermal neutron logs. The plotted results are volume fractions of sand and shale plotted versus depth, in the fourth panel (PANEL4) of FIG. 1, oil-based mud (OBM) filtrate saturation plotted versus depth, in the first panel (PANEL1) of FIG. 1, connate water and gas saturation in the invaded zone plotted versus depth in the first panel (PANEL1) of FIG. 1, and undisturbed zone gas saturation plotted versus depth in the second panel (PANEL2) of FIG. 1. The response equations of the four individual logs in the logging suite, plus the implied “unity” equation that specifies that the rock and fluid fractions sum to one, relate to the rocks and invaded zone fluids, so that up to five rock and fluid components may be quantified. Programs such as Schlumberger's ELAN that deliver a result by solving a determined or over-determined set of response equations are frequently used for this task. Total porosity plotted versus depth in the third panel (PANEL3) of FIG. 1 represents all the fluids present in the formation while effective porosity takes into account pore space where pores and pore throats are sufficiently large to allow fluid flow, hydrocarbon emplacement and production. As it can be appreciated, the term “saturation” is used for relative fractions of fluid within the porosity. The terms “volume, fraction or volume fractions” relate components to the whole formation, i.e., rocks plus fluids.
FIG. 2A-2D depicts a schematic conventional representation of clean sandstone and sandstone modified by the presence of structural, dispersed or laminated shale. In a clean sandstone, discrete sand grains make up a rigid pack and thus form pores therebetween, as depicted in FIG. 2A. In sandstone modified by the presence of shale, as in the case in many clastic reservoir sequences, the sandstone modified by the presence of shale may include intervals of thinly laminated sand and shale formations, as shown in FIG. 2D, and “shaley sand” intervals with evenly distributed shale within the pore space formed by the sand pack, as shown in FIG. 2C. However, in the case of “shaley-sand,” the shale may also be present as structural grain or “clasts” or forming part of the grain pack alongside the sand grains, as shown in FIG. 2B.
The conventional results plotted in FIG. 1 provide only information as to the overall proportion of sand and shale but do not provide any indication of the distribution of shale within the sand because the logs listed are sensitive only to the bulk volume fractions of the rocks, not their textural distribution. We refer to this as a “compositional analysis.”
It is assumed that variations in formation properties occur at a fine vertical scale, so the logs respond to the formation properties averaged over their vertical resolution which is about two feet for many common logs. The resolution is defined by the equipment or apparatus or measurement system (such as gamma ray Compton scattering or the slowing down length of high energy neutrons) used in the logs.
As can be seen, in FIGS. 2B-2D, three types of distribution of clay or shale within sandstone may be considered. The clay distribution has a significant effect on the petrophysical properties of the formation. Structural shale clasts, shown in FIG. 2B, replace sand grains leaving porosity and permeability essentially unchanged. Dispersed shale, or equally authigenic clay, shown in FIG. 2C fills the pore space, so a relatively small quantity reduces the pore space resulting in a significant drop in permeability, pore size and hydrocarbon volume fraction. In the laminated sequence, shown in FIG. 2D, the inherent properties of the sandy part of the rock are unchanged. Vertical permeability is zero, while horizontal permeability of the unit cube of formation is the same as for the clean sandstone, multiplied by the sand fraction. Similarly, in the laminated sequence, the effective porosity is equal to clean sand porosity multiplied the sand fraction.
These observations lead to plots or constructions such as that of Thomas and Stieber (TS) (see, Thomas E. C., and Stieber S. J., “The Distribution of Shale in Sandstones and its effect on Porosity,” 1975, SPWLA 16th Annual Logging Symposium and its Effect on Porosity, Paper T.). FIG. 3 depicts an example of a TS construction plotted in effective porosity format that uses the relationship between porosity and shale fraction to imply shale distribution. The y-axis represents the effective porosity and the x-axis represents the total shale fraction. The total shale fraction is the volume of shale divided by the total volume (the total volume being equal to the sum of the volume of the sand, the volume of the pores and the volume of the shale). This type of construction is referred herein as a “textural” analysis. As it can be appreciated, understanding the rock texture complements and adds value to the compositional analysis.
Computed porosity and shale fraction pairs from results of a computation such as that shown on FIG. 1 are plotted on a grid, such as the TS grid shown in FIG. 3. FIG. 3 illustrates an example for a formation with a clean sand porosity (on the y-axis) of 0.3, indicated as point M on FIG. 3. A porosity of zero represents a structure having substantially all shale, i.e., the total shale fraction (on the x-axis) is equal to 1.0 or 100%. A point with porosity equal to zero and a total shale fraction equal to 1.0 is indicated as point Z on FIG. 3. Points lying on the dotted line “L” from the “clean sand” maximum porosity point “M” to the zero porosity, 100% shale point “Z” represent laminated formations where the clean sand porosity is preserved in the sand laminations. The laminated shale fraction increases linearly along line “L”.
The solid lines forming nested recumbent chevron “V” patterns are lines of constant laminated shale fraction. Point “D” is the point where all the pore space is filled with dispersed shale. At point “D”, the dispersed shale fraction is 0.3 (30%) and the effective porosity is zero (the presence of shale in the pore space reduces the porosity to zero). The dispersed shale fraction at point “D” is equal to the maximum porosity at point “M” (i.e., 0.3). Structural shale, depicted in FIG. 2B, is assumed to replace sand grains without changing porosity since the structural shale simply replaces some grains of sand in the sandstone while the pores within the sandstone are left unchanged. The maximum theoretical structural shale porosity is therefore represented by point “S” where all sand grains have been replaced by structural shale. The x-axis value of point “S” is equal to one minus the porosity at point “M.” Lines of constant dispersed and structural shale lie parallel to line “L”.
A number of specific assumptions and limitations underlie the TS construction:
(a) a first assumption is that clean sand laminations maintain the same porosity, irrespective of the sand to laminated shale context. However, counterevidence from cores indicates that as the sand-shale ratio reduces, the sands become finer grained, less well sorted, and have lower porosity than thicker sand laminations;
(b) a second assumption is that the three shale types (i.e., structural shale, dispersed shale and laminated shale) have the same properties. However, considering the depositional conditions of (for example) a deep water turbidite sequence, the structural shale clasts are deposited under high energy conditions concurrently with the sand grains while the shale laminations are deposited during more quiescent periods. Material considered as dispersed shale may be authigenic clay minerals with quite distinct properties from the shale that contains clay minerals and other fine grained clastic material. Technology for quantifying several clay types exists, but requires more than the limited logging suite in this example, and in any case a more complete mineralogical interpretation could not be fed into the Thomas-Stieber (TS) construction in its conventional format.
(c) a first limitation is that the TS construction does not account for the possibility that structural and dispersed shale co-exist. For example, points lying on the laminated sand line “L” could equally have a wide range of balanced fractions of dispersed shale and structural shale.
Core descriptions and image logs can offer alternative independent estimates of laminated sand and shale fraction. The core descriptions and image logs are often considered quite reliable. However, in general, they differ from the results from the TS construction, and cannot easily be reconciled.
Despite these identifiable shortcomings, the TS construction is still commonly used in a sequential workflow where the textural analysis follows the compositional analysis. Therefore, there is a need for a method or methods that address these and other deficiencies in the conventional methods.